Materials with nanomaterials for well operations

ABSTRACT

Wellbore materials with nanomaterial therein, e.g., cements, polymers, composites, shape memory material, swellable material, and epoxies, and systems and methods using such materials, which, in certain aspects, are methods for cementing casing in a wellbore with such cement; the material being heatable material in some aspects, and being one or a combination of electrically resistively heatable material, microwave heatable material, and/or material heatable by the application thereto of a magnetic field. This abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure and is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims, 37 C.F.R. 1.72(b).

CROSS REFERENCE TO RELATED APPLICATIONS

The present application and invention claim, under the Patent Laws, priority from and under pending U.S. application Ser. No. 13/317,633 filed Oct. 24, 2011 and under and from U.S. Application Ser. No. 61/455,705 filed Oct. 25, 2010 and 61/516,589 filed Apr. 5, 2011—all said applications incorporated fully herein for all purposes. The present application is a Continuation-In-Part of pending U.S. application Ser. No. 13/317,633.

BACKGROUND OF THE INVENTION Field of the Invention

The present invention is directed to: wellbore operations; wellbore cement; wellbore cementing methods; methods for casing a well; methods for producing a well; such methods employing heatable cement; such methods having cement with resistively heatable electrically conductive material and/or inductively heatable material and/or microwave heatable material; swellable material; shape memory material; in certain particular aspects, to providing a wellbore with a casing string having all or a portion thereof cemented with cement having electrically conductive nanomaterial therein that is heatable by imposing an electric current thereon thereby heating the cement; and to methods for wellbore operations using material with nanomaterial therein (e.g., cements, polymers, composites, swellable materials, shape memory materials, and/or epoxy systems), and to operations with such materials having resistively heatable electrically conductive material and/or inductively heatable material and/or microwave heatable material to facilitate heating, hardening, setting, and/or curing.

There are a multitude of known systems and methods for completing a wellbore for oil and gas production, including many known casing methods and methods for cementing casing in a wellbore. There are many known cements used in such systems and methods.

FIG. 1 shows schematically and not to scale a typical cased wellbore with casing cemented in place in the wellbore with cement. The casing extends from an earth surface down to the bottom of the wellbore and the casing is usually cemented along its length.

There have long been needs, recognized by the present inventor, for heatable cement for wellbore operations, for effective well completion methods and systems, and for enhanced methods and systems for producing fluids from a wellbore.

SUMMARY OF THE PRESENT INVENTION

The present invention discloses swellable materials, shape memory materials, and cements with nanomaterial therein; and methods for using such materials in wellbore operations. In certain aspect, using such cements for cementing casing in a wellbore, the methods include cementing at least a portion of a casing in a wellbore with cement that contains one or a combination of: resistively heatable electrically conductive material; inductively heatable material; microwave heatable material; and/or electrically conductive nanomaterial.

The present invention discloses cements and methods for using such cements for cementing casing in a wellbore, the methods including cementing at least a portion of a casing in a wellbore with cement that contains electrically conductive nanomaterial. In certain aspects, the present invention discloses materials, systems, and methods for facilitating the hardening, setting, and/or curing of material within a wellbore (e.g., but not limited to, polymers, composites, epoxy systems, and cements) and/or within a wellbore structure (downhole or above ground) by employing material that contains one or a combination of: resistively heatable electrically conductive material; inductively heatable material; microwave heatable material; and/or electrically conductive nanomaterial.

The present invention, in certain aspects, discloses a cased cemented wellbore and methods for making such a wellbore that has at least a part of, parts of, or all of the cement containing electrically conductive nanomaterial therein so that part, parts, or all of the cement is heatable by imposing an electric current on the electrically conductive nanomaterial resulting in resistive heating of the cement, and, if desired, things in contact with or near the cement. The current may be either alternating current or direct current. Such heating may also facilitate curing, solidifying, and/or setting of the cement. In one aspect, material (e.g., shape memory material, swellable material, cement, polymer, composite, epoxy system) according to the present invention has nanomaterials therein for strengthening, and/or for electrical conductivity and/or for signal conductivity, which are in certain aspects electrically conductive, for example, and not limited to, electrically conductive nanotubes, nanographene, nanographene ribbons, and/or transformed nanomaterials and carbon nanomaterials, e.g., but not limited to, carbon nanotubes. Nanomaterial and/or electrically conductive nanomaterial in embodiments of the present invention may include one or a variety of nanotubes, including, but not limited to single-walled nanotubes, multi-walled nanotubes, double walled nanotubes, and/or surface-modified nanotubes. “Nanomaterial” includes, without limitation, one, some or any combination of these materials and/or nanotubes.

It is within the scope of the present invention to impose a magnetic field on inductively heatble material, to impose an electric current on electrically conductive material, and/or to impose an electrical current on electrically conductive nanomaterial in material (e.g., in cement, polymer, epoxy system) according to the present invention using any suitable magnetic field generator, induction coil apparatus, and/or power system and/or control system and/or connectors, connections, leads, metal tubulars themselves, wires and/or power cables, insulated or not, in the earth adjacent the material, in the material, on the exterior of a tubular and/or on the interior of a tubular. Optionally, electric current is sent via a transmitted wave or signal (with a wired system and/or wirelessly) to a suitable receptor for conversion to electrical current for application to the material. Optionally, a generator in the earth, in the wellbore, or in a tubular in the wellbore generates the needed electricity to produce heat.

Heat generated in material (e.g., in cement, in polymers, swellable material, shape memory material, in an epoxy system) according to the present invention and/or in systems according to the present invention can be used to heat the material and, in certain aspects, to heat things and materials either in contact with the material or in proximity to the material; e.g., but not limited to, tubulars (e.g., casing, collars, pipe, or tubing), fluid and/or materials in such tubular, fluid and/or materials outside a tubular, e.g. fluid or materials in an annulus between a tubular exterior and a wellbore or tubular exterior, and earth or formations adjacent the material; e.g., but not limited to, adjacent cement in a wellbore.

Accordingly, the present invention includes features and advantages which are believed to enable it to advance wellbore technology and wellbore production technology. Characteristics and advantages of the present invention described above and additional features and benefits will be readily apparent to those skilled in the art upon consideration of the following description of preferred embodiments and referring to the accompanying drawings.

Certain embodiments of this invention are not limited to any particular individual feature disclosed here, but include combinations of them distinguished from the prior art in their structures, functions, and/or results achieved. Features of the invention have been broadly described so that the detailed descriptions of embodiments preferred at the time of filing for this patent that follow may be better understood, and in order that the contributions of this invention to the arts may be better appreciated. There are, of course, additional aspects of the invention described below and which may be included in the subject matter of the claims to this invention. Those skilled in the art who have the benefit of this invention, its teachings, and suggestions will appreciate that the conceptions of this disclosure may be used as a creative basis for designing other structures, methods and systems for carrying out and practicing the present invention. The claims of this invention are to be read to include any legally equivalent devices or methods which do not depart from the spirit and scope of the present invention.

What follows are some of, but not all, the objects of this invention. In addition to the specific objects stated below for at least certain embodiments of the invention, other objects and purposes will be readily apparent to one of skill in this art who has the benefit of this invention's teachings and disclosures. It is, therefore, an object of at least certain embodiments of the present invention to provide the embodiments and aspects listed above and:

New, useful, unique, efficient, nonobvious systems and methods for completing a wellbore for fluid production therefrom;

New, useful, unique, efficient, nonobvious wellbore casing cements which include inductively heatable material, electrically conductive material, and/or electrically conductive nanomaterial therein to heat the cement and, in some aspects, material and/or earth in contact with and/or adjacent the heated cement;

New, useful, unique, efficient, nonobvious wellbore materials with nanomaterial therein; and cements and systems and methods for cementing casing in a wellbore; and

New, useful, unique, efficient, nonobvious systems and methods for heating all, a part of, or parts of cement that cements casing in a wellbore.

New, useful, unique, efficient, nonobvious wellbore materials which include new and nonobvious swellable materials; new and nonobvious shape memory materials; and new and nonobvious inductively heatable material, electrically conductive material, microwave heatable material, and/or electrically conductive nanomaterial therein to heat the wellbore material (e.g., cement, polymers, swellable material, shape memory material, composites, epoxy systems, e.g., but not limited to, two-part epoxy systems) and, in some aspects, material and/or earth in contact with and/or adjacent the heated material; and

New, useful, unique, efficient, nonobvious systems and methods for heating all, a part of, or parts of material in a wellbore e.g, but not limited to, cement that cements casing in a wellbore.

The present invention recognizes and addresses the problems and needs in this area and provides a solution to those problems and a satisfactory meeting of those needs in its various possible embodiments and equivalents thereof. To one of skill in this art who has the benefits of this invention's realizations, teachings, disclosures, and suggestions, various purposes and advantages will be appreciated from the following description of certain preferred embodiments, given for the purpose of disclosure, when taken in conjunction with the accompanying drawings. The detail in these descriptions is not intended to thwart this patent's object to claim this invention no matter how others may later attempt to disguise it by variations in form, changes, or additions of further improvements.

The Abstract that is part hereof is to enable the U.S. Patent and Trademark Office and the public generally, and scientists, engineers, researchers, and practitioners in the art who are not familiar with patent terms or legal terms of phraseology to determine quickly, from a cursory inspection or review. the nature and general area of the disclosure of this invention. The Abstract is neither intended to define the invention, which is done by the claims, nor is it intended to be limiting of the scope of the invention or of the claims in any way.

It will be understood that the various embodiments of the present invention may include one, some, or all of the disclosed, described, and/or enumerated improvements and/or technical advantages and/or elements in claims to this invention.

Certain aspects, certain embodiments, and certain preferable features of the invention are set out herein. Any combination of aspects or features shown in any aspect or embodiment can be used except where such aspects or features are mutually exclusive.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

A more particular description of embodiments of the invention briefly summarized above may be had by references to the embodiments which are shown in the drawings which form a part of this specification. These drawings illustrate embodiments preferred at the time of filing for this patent and are not to be used to improperly limit the scope of the invention which may have other equally effective or legally equivalent embodiments.

FIG. 1 is a schematic view—not to scale—of a prior art cased cemented wellbore.

FIG. 2 is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 3 is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 4 is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 5A is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 5B is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 5C is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 5D is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 6 is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 7 is a schematic view—not to scale—of a cased cemented wellbore according to the present invention.

FIG. 8A is a side cross-sectional view of a well bore and a casing to be cemented therein having a cementing plug assembly installed in its initial position in the casing.

FIG. 8B is a view similar to FIG. 8A, but showing the well bore and casing after a displacement plug of the cementing plug assembly has been released and landed on a float collar in the casing.

FIG. 8C is a view similar to FIG. 8B, but showing the well bore and casing after a bottom plug of the cementing plug assembly has been released and landed on the displacement plug.

FIG. 8D is a view similar to FIG. 8C, but showing the well bore and casing after a top plug of the cementing plug assembly has been released and landed on the bottom plug.

FIG. 9A is a fragmentary cross-sectional illustration of an embodiment of a step in a method according to the present invention.

FIG. 9B is a fragmentary cross-sectional illustration of an embodiment of a step in a method according to the present invention after the previous step.

FIG. 9C is a fragmentary cross-sectional illustration of an embodiment of a step in a method according to the present invention.

FIG. 9D is a fragmentary cross-sectional illustration of an embodiment of a step in a method according to the present invention after the previous step.

FIG. 9E is a fragmentary cross-sectional illustration of an embodiment of a step in a method according to the present invention after the previous step.

FIG. 10A is a side schematic view of a cementing system connected to a well head with suitable piping for making a cemented wellbore according to the present invention and includes a cement delivery system and well head.

FIG. 10B is a side schematic view of a cemented wellbore according to the present invention showing a casing with cement in an annular space with zones with different cement.

FIG. 10C is a side schematic view of a cemented wellbore according to the present invention showing a casing with cement in an annular space with zones with different cement.

FIG. 11 a side schematic view of a cemented wellbore according to the present invention.

FIG. 12 a schematic view of a system and method according to the present invention. Nanomaterial is not depicted to scale in any drawing.

FIG. 13 is a schematic view of a system using swellable material according to the present invention.

FIG. 14A is a crosssection view of material according to the present invention.

FIG. 14B is a crosssection view of the material of FIG. 14A post-expansion.

FIG. 15A is a crosssection view of material according to the present invention.

FIG. 15B is a crosssection view of material according to the present invention.

FIG. 15C is a crosssection view of material according to the present invention.

FIG. 15D is a crosssection view of the material of FIG. 15A post-expansion.

FIG. 16A is a perspective view of a tubular with swellable material according to the present invention.

FIG. 16B is a cutaway view of the tubular of FIG. 16A.

Certain embodiments of the invention are shown in the above-identified figures and described in detail below. Various aspects and features of embodiments of the invention are described below and some are set out in the dependent claims. Any combination of aspects and/or features described below or shown in the dependent claims can be used except where such aspects and/or features are mutually exclusive. It should be understood that the appended drawings and description herein are of certain embodiments and are not intended to limit the invention or the appended claims. On the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims. In showing and describing these embodiments, like or identical reference numerals are used to identify common or similar elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

As used herein and throughout all the various portions (and headings) of this patent, the terms “invention”, “present invention” and variations thereof mean one or more embodiments, and are not intended to mean the claimed invention of any particular appended claim(s) or all of the appended claims. Accordingly, the subject or topic of each such reference is not automatically or necessarily part of, or required by, any particular claim(s) merely because of such reference. So long as they are not mutually exclusive or contradictory any aspect or feature or combination of aspects or features of any embodiment disclosed herein may be used in any other embodiment disclosed herein. The drawing figures present the embodiments preferred at the time of filing for this patent.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

It is within the scope of the present invention, in any embodiment described below, to substitute for the electrically conductive nanomaterial, electrically conductive material that is sufficiently resistively heatable to effect the desired heating and/or microwave heatable material. It is within the scope of the present invention, in any embodiment described below, to substitute for the electrically conductive nanomaterial, inductively heatable material that is sufficiently inductively heatable to effect the desired heating and/or microwave heatable material; and in such embodiments, any power source below may be changed to a magnetic field apparatus useful in inductive heating, e.g., but not limited to, induction coil apparatuses and/or changed to a suitable apparatus for applying microwaves to microwave heatable material. It should also be understood that it is within the scope of the present invention to use a combination of any of these materials—electrically conductive material, inductively heatable material, microwave heatable material, and electrically conductive nanomaterial—in a single material in or for introduction into a wellbore, e.g., but not limited to, cements, polymers, shape memory material, swellable material, composites, and/or epoxy systems, including, but not limited to, two-part epoxy systems and, in certain particular aspects, in a single cement or in a single zone of a wellbore.

FIG. 2 shows a cemented cased wellbore Q with electrically conductive nanomaterial NM (e.g., but not limited to, carbon nanotubes) throughout the cement. Electricity is imposed on the nanomaterial in the cement via leads A and B. As is true for any embodiment described below, the material NM may be replaced by, or used with, one or a combination of (combinations including any two or three of these materials or a combination of any one or two of them with electrically conductive nanomaterial) resistively heatable electrically conductive material; inductively heatable material; microwave heatable material. “Microwave heatable material” as used herein may include any of the nanomaterials disclosed or referred to herein that is microwave heatable.

FIG. 3 shows a cemented cased wellbore R with electrically conductive nanomaterial NM (e.g., but not limited to, carbon nanotubes) in discrete portions X and Y of the cement. Electricity is imposed on the cement portion X via leads C and D and/or the cement portion Y by leads E and F (all leads going to a power source either in the well or at the surface).

It is within the scope of the present invention to have any number of spaced-apart portions of cement in a wellbore (e.g., one, two, three, four or multiple portions throughout a wellbore or multiple spaced-apart portions in an area of a wellbore adjacent a particular formation) with electrically conductive nanomaterial therein so that any part of the wellbore and of adjacent formation can be selectively heated.

FIG. 4 shows a perforated zone Z in a cased cemented wellbore S with electrically conductive nanomaterial NM in the cement adjacent the perforated zone. This part of the cement in the zone Z can be selectively heated via leads G and H with a power source PS at the surface or with a power source PC in the well, or with both. Any suitable AC or DC power source or sources may be used (as is true for any embodiment according to the present invention). It is believed that heating the formation FO around the zone Z may, in some cases, facilitate production from the formation. As is true for any embodiment of the present invention (including, but not limited to, those described above and below) instead of or in addition to the power source PS, depending on the material to be heated, a magnetic field apparatus may be used and/or an apparatus for applying microwaves to microwave heatable material may be used and the subject matter of the various drawing figures that shows a power source may be changed so that the power source is deleted and a magnetic filed source and/or microwave source is used.

FIG. 5A shows a cased cemented wellbore 1 with electrically conductive nanomaterial NM (not to scale) in cement T with one lead C at the bottom of the cement and extending up through the earth and one lead D extending through the earth to an upper part of the cement.

FIG. 5B shows a cased cemented wellbore 2 with electrically conductive nanomaterial NM (not to scale) in cement T with one lead E at the top of the cement and connected to the interior of the casing and one lead F extending through the earth to the bottom of the cement T. The lead E may be insulated and may pass through the casing to contact the cement.

FIG. 5C shows a cased cemented wellbore 3 with electrically conductive nanomaterial NM (not to scale) in cement T with one lead G at the top of the cement and connected to the interior of the casing and one lead H extending through the casing's interior to the bottom of the cement T. The leads may contact the casing itself or the leads may be insulated and may pass through the casing to contact the cement.

FIG. 5D shows a cased cemented wellbore 4 with electrically conductive nanomaterial NM (not to scale) in cement T with one lead K at the top of the cement and passing through or connected to the interior of the casing and one lead L extending through the earth to the bottom of the cement T. The lead K may contact the casing itself or the lead K may be insulated and may pass through the casing to contact the cement.

Power may be supplied to the leads of the systems of FIGS. 5A-5D via a surface power generator PG (see e.g. FIG. 5A) or via a power generator PE in the earth (see FIG. 5B), or via a power generator PR within the casing (see FIG. 5C). Optionally, a power source PU either at the surface, as shown, or in the casing or in the earth (not shown) receives a wave or signal from an appropriate device or system and converts the wave or signal to electric power for application to the leads K and L. Power may be supplied to any system or cement according to the present invention with any of the power sources of FIGS. 5A-5D. When inductively heatable material is used instead or or in addition to cement, a magnetic field is applied the inductively heatable material via a surface apparatus or via an apparatus in the earth, or via an apparatus within the casing. Optionally, such an apparatus either at the surface or in the casing or in the earth receives a wave or signal from an appropriate device or system and converts the wave or signal to power for application of the magnetic field. When microwave heatable material is used instead of or in addition to cement and/or inductively heatable material, microwaves are applied the inductively heatable material via a surface apparatus or via an apparatus in the earth, or via an apparatus within the casing. Optionally, such an apparatus either at the surface or in the casing or in the earth receives a wave or signal from an appropriate device or system and converts the wave or signal to power for application of the microwaves.

As is true of any wellbore, any system and any method according to the present invention, a cased wellbore according to the present invention, as exemplified by the wellbores in the drawing figures hereof, can be made with any known drilling and completion method that involves the cementing of casing in a wellbore, including, but not limited to, typical drilling and cementing operations and also, without limitation, casing drilling methods, rotary drilling methods, top drive drilling methods and coiled tubing drilling methods.

FIG. 6 shows a wellbore 60 according to the present invention in the earth 67. Casing 61 is cemented in the wellbore 60 with cement 62. Portions 63, 64 and 65 of the cement 62 have electrically conductive nanomaterial NM therein. The portions 63, 64, 65 are spaced-apart any desirable distance and they may be located adjacent different earth formations. There may be the three portions shown or, according to the present invention, there may be two or any number of such portions at any part of or throughout the wellbore.

A power supply 66 supplies electrical current to the nanomaterial NM in the portions 63, 64, 65. All portions can be heated simultaneously; one or two portions may be selectively heated; or the portions may be sequentially heated from top to bottom or from bottom to top.

FIG. 7 shows a wellbore 70 according to the present invention in the earth 77. Casing 71 is cemented in the wellbore 70 with cement 72. Portions 73, 74 and 75 of the cement 72 have electrically conductive nanomaterial NM therein. The portions 73, 74, 75 are spaced-apart any desirable distance and they may be located adjacent different earth formations. There may be the three portions shown or, according to the present invention, there may be two or any number of such portions at any part of or throughout the wellbore.

A power supply 76 (within the earth as shown or at the surface or within the wellbore—as is true for the power supply 66) supplies electrical current to the nanomaterial NM in the portions 73, 74, 75. All portions can be heated simultaneously; one or two portions may be selectively heated; or the portions may be sequentially heated from top to bottom or from bottom to top.

As shown in FIG. 7, the density (or concentration) of nanomaterial NM in the portion 73 is less than the density of nanomaterial NM in the portion 74; and the density of nanomaterial NM in the portion 75 is denser than that of the nanomaterial NM in the portion 74. In one aspect, it is possible to heat the portion 75 faster than the portions 74 and 73 due to the presence of more nanomaterial per unit volume in the portion 75; and/or it is possible to heat the portion 75 to a higher temperature than the other two portions for the same reason. It is to be understood that heating of the portions 63-65 and/or 73-75, can, according to the present invention, be used to heat the earth in contact with or adjacent these portions and/or to heat the casing adjacent these portions and/or the contents of the casing adjacent these portions. In Any embodiment herein, the nanomaterial may be present at any level, at any desired weight percent for effecting, e.g., an increase in strength, an increase in thermal conductivity, and/or an increase in electrical conductivity; e.g., the nanomaterial may be present between 0.1 and 10 weight percent.

The power supplies 66 and 76 and the leads, cables, connections, etc. for them may be any power source or supply and leads, etc. disclosed herein. Any control system may be used with the power supplies 66 and 76, e.g. like the control system CS FIG. 10A or any of the options disclosed for the system CS.

The present invention provides improvements to various existing wellbore cementing methods. In one aspect, the present invention provides methods which in some ways are similar to those disclosed in U.S. Pat. No. 5,829,523, incorporated fully herein for all purposes. In certain embodiments of the present invention, in cementing casing or liners (both referred to hereinafter as “casing”) in well bores (sometimes referred to as “primary cementing”), a cement slurry containing electrically conductive nanomaterial is pumped downwardly through the casing to be cemented and then upwardly into the annulus between the casing and the walls of the well bore. Upon setting, the cement bonds the casing to the walls of the well bore and restricts fluid movement between formations or zones penetrated by the well bore. Prior to this, the casing is suspended in a well bore and both the casing and the well bore are filled with drilling fluid. In order to reduce contamination of the cement slurry at the interface between it and the drilling fluid, a cementing plug for sealingly engaging the inner surfaces of the casing is pumped ahead of the cement slurry whereby the cement slurry is separated from the drilling fluid as the cement slurry and drilling fluid ahead of it are displaced through the casing. The cementing plug wipes the drilling fluid from the walls of the casing and maintains a separation between the cement slurry and drilling fluid until the plug lands on a float collar attached near the bottom end of the casing.

The cementing plug which precedes the cement slurry and separates it from drilling fluid is referred to herein as the “bottom plug.” When the predetermined required quantity of the cement slurry has been pumped into the casing, a second cementing plug, referred to herein as the “top plug”, is released into the casing to separate the cement slurry from additional drilling fluid or other displacement fluid used to displace the cement slurry. When the bottom plug lands on the float collar attached to the casing, a valve mechanism opens which allows the cement slurry to proceed through the plug and the float collar upwardly into the annular space between the casing and the well bore. The design of the top plug is such that when it lands on the bottom plug it shuts off fluid flow through the cementing plugs which prevents the displacement fluid from entering the annulus. After the top plug lands, the pumping of the displacement fluid into the casing is continued whereby the casing is pressured up and the casing and associated equipment including the pump are pressure tested for leaks or other defects.

The present invention provides, in certain aspects, methods which include releasing a first displacement plug (e.g., but not limited to, as in U.S. Pat. No. 5,829,523) into the casing which is selectively openable after landing on a float collar. A first displacement fluid is then pumped behind the first displacement plug while measuring the quantity of the first displacement fluid being pumped until the first displacement plug is displaced through the casing and lands on a float shoe contained in the casing. The first displacement plug is caused to open, and a cement slurry which has nanomaterials therein (any cement according to the present invention) is pumped into the casing in a predetermined quantity required to fill the annulus between the exterior of the casing and the walls of the well bore with the cement slurry. After the predetermined quantity of cement slurry is pumped into the casing, a top cementing plug is released into the casing. A second displacement fluid is then pumped behind the top cementing plug to displace the cement slurry through the casing and through the open displacement plug into the annulus. The second displacement fluid is pumped in a quantity substantially equal to the quantity of the first displacement fluid as measured during the displacement of the first displacement plug thereby ensuring that the cement slurry is not under or over displaced in the annulus.

As shown in FIGS. 8A-8D, a well cementing plug assembly (any known suitable assembly, e.g., but not limited to, as shown in U.S. Pat. No. 5,829,523) is illustrated and generally designated by the numeral 810. The plug assembly 810 is shown positioned within a string of casing 812 which is suspended in a well bore 814 preparatory to being cemented therein. The plug assembly 810 is in its initial position in the casing 812 whereby it is releasably connected to the lower end of a string of drill pipe or a conventional circulation tool 816. The casing 812 includes a conventional float collar 824 connected therein near the bottom thereof. A conventional float shoe 832 is connected to the bottom end of the casing 812 separated from the float collar 824 by a distance 830.

In one version of a cementing plug assembly 810, the assembly has a selectively operable displacement plug 818 which is releasably connected to a selectively operable bottom cementing plug 820. The bottom cementing plug 20 is in turn releasably connected to a top cementing plug 822. The top cementing plug 822 is releasably connected to the drill pipe or circulation tool 816.

The displacement plug 818 and bottom cementing plug 820 are both separately closed and released by dropping different sizes of releasing plugs, e.g., balls, therein and then increasing the differential fluid pressures exerted on the plugs to predetermined differential fluid pressures which cause their release as will be described further herein below. When the displacement plug 818 lands on the float shoe 824 and when the bottom plug 820 lands on the displacement plug 818, the plugs are separately caused to open. That is, the displacement and bottom plugs are opened by again increasing the differential fluid pressures exerted on them to predetermined differential fluid pressures. The top cementing plug 822 is also closed and released by dropping a releasing plug, e.g., a drill string or tubing plug, therein and exerting a predetermined differential fluid pressure thereon.

Both the casing 812 to be cemented and the well bore 814 are usually filled with drilling fluid prior to commencing primary cementing operations. After suspending the casing string 812 in the well bore 814 and positioning the cementing plug assembly 810 within the casing 812 as shown in FIG. 8A, a releasing plug RP of a predetermined relatively small size is dropped into and caused to be moved in a known manner through the drill string or circulation tool 816, through the plug assembly 810 and into the displacement plug 818. The releasing plug closes the displacement plug 818 and a first predetermined differential fluid pressure is then exerted on the displacement plug 818 which causes its release from the assembly 810. A first displacement fluid, such as drilling fluid, is pumped behind the closed displacement plug so that the displacement plug is moved through the casing and lands on the float collar 824 as shown in FIG. 8B. The displacement plug 818 slidably and sealingly engages the walls of the casing 812 as it is moved through the casing and it separates and prevents mixing of the fluids on its opposite sides, i.e., drilling fluid 826 below the displacement plug 818 which was in the casing prior to the release of the displacement plug 818 and the first displacement fluid 828 above the displacement plug 818. Optionally, as the displacement plug 818 is moved through the casing 812, the quantity of the first displacement fluid being pumped is measured by a volume meter, a pump stroke counter or other volume measurement device whereby when the displacement plug 818 lands on the float collar 824, the total quantity of displacement fluid required to move the displacement plug 818 from the assembly 810 to the float shoe is known.

When the displacement plug 818 lands on the float collar 824, the movement of the displacement plug 818 and the flow of the first displacement fluid is stopped whereby the pressure within the casing 812 above the displacement plug 818 is increased. Such pressure increase is seen in the displacement fluid pressure indicated at the surface whereby the drilling rig operator knows the displacement plug 818 has landed and can then observe or otherwise determine the total quantity of the first displacement fluid pumped. Thereafter, the first displacement fluid pressure is increased by continued pumping until a second predetermined differential fluid pressure is reached which opens the displacement plug 818 in a manner which will be described herein below.

A length 830 of the casing 812 extends between the float collar 824 and the float shoe 832 attached to the bottom end of the casing 812. The length of casing 830 between the float collar 824 and the float shoe 832 is known in the art as the shoe track and will be referred to hereinafter as the shoe track 830. During the travel of the displacement plug 818 from the assembly 810 to the float collar 824, the drilling fluid 826 below the displacement plug 818 is displaced through the float collar 824, through the shoe track 830 and through the float shoe 832 into the annulus 834 between the casing 812 and the walls of the well bore 814. Once the displacement plug 818 has landed on the float collar 824, the total quantity of the first displacement fluid pumped has been measured and the displacement plug 818 has been opened, a second releasing plug of a predetermined medium size as compared to the first releasing plug is dropped into the bottom cementing plug 820 whereby the bottom cementing plug 820 is closed. A cement slurry 836 is then pumped through the drill string or circulation tool 816 whereby a third predetermined differential fluid pressure is exerted on the bottom cementing plug 820 and it is released. The cement slurry contains electrically conductive nanomaterial NMT (not shown to scale; any such nanomaterial disclosed herein according to the present invention). The cement slurry 836 is pumped into the casing 812 behind the bottom plug 820 in a predetermined quantity required to fill the annulus 834. As the bottom plug 820 moves through the casing 812, the first displacement fluid 828 is displaced through the displacement plug 818, through the float collar 824, through the shoe track 830, through the float shoe 32 and into the annulus 834. The cement slurry 836 is pumped, and if necessary displaced, into the casing 812 until the bottom plug 820 lands on the displacement plug 818 as shown in FIG. 8C. The pumping or displacement of the cement slurry 836 is then continued to increase the fluid pressure exerted on the bottom cementing plug 820 until a fourth predetermined differential fluid pressure is reached which causes the bottom cementing plug 820 to open and the cement slurry 836 to flow through it, through the displacement plug 818, through the float collar 824, through the shoe track 830, through the float shoe 832 and into the annulus 834.

When the predetermined quantity of cement slurry 836 has been pumped into the casing 812, a third releasing plug of a predetermined large size as compared to the second releasing plug is dropped into the top cementing plug 822 which closes the top cementing plug 822. A second displacement fluid 838, which preferably is the same as or at least has very similar properties to the first displacement fluid 828 used, is pumped behind the top cementing plug 822. The fluid pressure exerted on the top cementing plug 822 by the second displacement fluid 838 is increased to a fifth predetermined differential fluid pressure which causes the top cementing plug 822 to be released. Thereafter, a quantity of the second displacement fluid 838 substantially equal to the previously measured quantity of the first displacement fluid 828 is pumped. The pumped quantity of the second displacement fluid 838 is preferably measured using the same flow meter or other measuring device which was used to measure the quantity of the first displacement fluid thereby assuring that the two quantities are the same or substantially the same.

The cement slurry 836 is displaced through the casing 812, through the bottom cementing plug 820, through the displacement plug 818, through the float collar 824, through the shoe track 830 and through the float shoe 832 into the annulus 834 as shown in FIG. 8D. When the top cementing plug 822 lands on the bottom cementing plug 820, the top cementing plug terminates the flow of the second displacement fluid 838 and prevents it from flowing into the shoe track 830 or the annulus 834. The pumping of the measured quantity of the second displacement fluid 838 allows the rig operator to know that the top plug 822 has landed whereupon the operator can proceed to pressure test the casing 812 and associated equipment. The cement slurry 836 in the annulus 834 and the shoe track 830 is then allowed to set whereby the casing 812 and shoe track 30 are cemented in the well bore. Thereafter, the displacement plug 818, the cementing plugs 820 and 822, the internals of and set cement in float collar 824, the set cement in the shoe track 830 and the internals of and set cement in the float shoe 832 are all drilled out of the casing 812 whereupon the well is completed or additional well bore is drilled below the casing 812.

In accordance with certain aspects of the present invention, the quantity of the second displacement fluid 838 utilized for displacing the top cementing plug 822 and the cement slurry 836 through the casing 812 and into the annulus 834 is a quantity substantially equal to the quantity of the first displacement fluid 828 measured when the displacement plug 818 was displaced through the casing 812 with the first displacement fluid 828. The first and second displacement fluids are preferably the same or very similar fluids, e.g., drilling fluid, and are preferably measured by the same flow meter or other measuring device to ensure as much as possible that the quantities of the first and second displacement fluids are equal or at least substantially equal. Thus, the quantity of the second displacement fluid 838 required to displace the cement slurry 836 into the annulus 834 and land the top cementing plug 822 is positively determined.

It is within the scope of the present invention that some operators may prefer to omit the use of the bottom cementing plug 820, and instead utilize a two plug assembly consisting of the displacement plug 818 and the top cementing plug 820. Also it is within the scope of the present invention that the displacement plug and one or two cementing plugs used be released from the surface separately in any suitable manner and do not necessarily need to be releasably connected in an assembly as described above.

A wellbore made as in FIGS. 8A-8D may have any device or system described herein for imposing a current on the nanomaterial in the cement.

Referring to FIG. 9A, a method 910 according to the present invention is illustrated for cementing a wellbore 912 which employs a system that includes a shoe 914 defining a passage 914 a that is coupled to an end of a tubular member 916 defining a passage 916 a. The tubular member 916 includes one or more tubular members threadably coupled end to end. The other end of the tubular member 916 is coupled to an end of a float collar 918 including a float 918 a. The other end of the float collar 918 is coupled to an end of a tubular member 920 defining a passage 920 a. Centralizers 922 a, 922 b, and 922 c are coupled to the exteriors of the tubular members, 916 and 918. More generally, the system may include any number of centralizers. The other end of the tubular member 920 is coupled to a fluid injection assembly 924 defining a passage 924 a and radial passages 924 b, 924 c, and 924 d, and including retaining pins 924 e and 924 f. The fluid injection head 924 is commonly referred to as a cementing head. A bottom cementing plug 926 and a top cementing plug 928 are retained within the passage 924 a of the fluid injection assembly 924 by the retaining pins 924 e and 924 f. The bottom cementing plug 926 typically includes a longitudinal passage that is sealed off by a frangible diaphragm.

During operation, as illustrated in FIG. 9A, drilling mud 930 is circulated through the wellbore 912 by injecting the drilling mud into the fluid injection assembly 924 through the radial passage 924 b. The drilling mud 930 then passes through the passages 924 a, 920 a, 918 a, and 914 a into the annulus between the tubular member 920, the float collar 918, the tubular member 916, and the shoe 914. As illustrated in FIG. 9B, the bottom cementing plug 926 is then released and a spacer fluid 932 followed by a cement slurry 934 are injected into the injection assembly 924 through the radial passage 924 c behind and above the bottom cementing plug. The cementing slurry 934 contains sufficient electrically nanomaterial NML (not shown to scale) that upon the imposition of an electric current thereon, the nanomaterial NML is resistively heated which in turn heats cement resulting from setting and hardening of the cement slurry 934. As illustrated in FIG. 9C, the top cementing plug 928 is then released and a displacing fluid 936 is injected into the injection assembly 924 through the radial passage 924 d behind and above the top cementing plug. As illustrated in FIG. 9D, the continued injection of the displacing fluid 936 displaces the bottom cementing plug 926 into contact with the float collar 918 and breaks the frangible membrane of the bottom cementing plug thereby causing the cement slurry 934 to flow into the annulus between the wellbore 912 and the shoe 914, the tubular member 916, the float collar 918, and the tubular member 920. As illustrated in FIG. 9E, the continued injection of the displacing fluid 936 then displaces the top cementing plug 928 downwardly until the top cementing plug impacts the bottom cementing plug 926. The float element 918 a of the float collar 918 prevents back flow of the cement slurry 934 into the tubular member 920. The cement slurry 934 may then be allowed to cure.

A wellbore made as in FIGS. 9A-9E may have any device or system described herein for imposing a current on the nanomaterial in the cement.

As shown in FIG. 10A, a wellbore 1000 according to the present invention has multiple zones (Sectors 1, 2,3) with different cements 1027, 1026, 1025, respectively, according to the present invention which can be any cement disclosed herein according to the present invention. Electrically conductive nanomaterial is represented schematically by the material NME, NMF, NMG (may be different materials, similar materials, at the same or at different concentrations; not to scale). The cements can be prepared off site, or, as shown, can be mixed in the field and delivered through pumps 1011 into a manifold 1012. The manifold is connected to a well head at 1013. As appropriate, a suitable valve (or valves) 1014 is interposed between them. The cement is delivered under suitable pressures at selected flow rates. The nature of the cement is variable and the cements 1025-1027 may each be any cement disclosed herein according to the present invention; and they may each be a different cement, any two of them may be the same, or they may all three be the same. It is to be understood that a wellbore according to the present invention may have any multiple number of cement zones, although only three are depicted in FIG. 10A. Optionally, a supply apparatus 1010 may supply different cements and/or other fluids to be used in the cementing process. In certain aspects, two or three different cements and/or fluids may be pumped into the well to complete the cementing job. The manifold 1012 is used to deliver these cements and/or fluids into the well. The pump 1011 is connected with suitable supplies of various fluids for delivery into the well.

At the wellhead, an optional flow meter 1015 measures the rate of flow which can be expressed in barrels per minute. This is the rate of flow of the cement and/or fluid delivered into the well. The density of the fluid can also, optionally, be measured at the wellhead by a transducer 1016. Density may be indicated in pounds per gallon. As appropriate, a fluid analysis device 1017 may be incorporated to make other measurements regarding the cement and/or fluid. Transducers 1015, 1016 and device 1017 form output data which is input to an analysis and control system CS which controls the flow of the cement and/or fluid (the control system CS may be any suitable known control system, including, but not limited to, those disclosed in prior patents referred to herein). Any wellbore and method disclosed herein according to the present invention may have one or more of the control systems CS. Pressure at the wellhead may be measured by a device 1018 and may be expressed in pounds per square inch. The pressure device 1018 may be calibrated up to several thousand psi. Pressures in this range are not uncommon.

The wellhead 1013 is connected to a completion string in a wellbore 1020. The wellbore 1020 may, according to the present invention, be cased or open hole, and is represented in a very general form in FIG. 10A. While there may be multiple completion strings, FIG. 10A shows a representative single completion string in the well. This is the string of pipe (or casing) to be cemented in place in the well; this string of pipe can enclose a separate tubing string or strings to conduct produced fluids, e.g. oil and/or gas, to the surface. This string can be uniform from top to bottom, but it can also be made in different sections. To this end, an upper section is identified by the numeral 1021. This section is casing or tubing of a specific diameter and flow characteristic and has a certain length and extends to a selected depth in the bore hole. The number 1022 identifies a second section which is serially connected to a third section 1023. The sections 1021, 1022, and 1023 jointly comprise the completion string. They may be identical and to that degree only a single section need be mentioned. On the other hand, when they are different, they may be different lengths and may be formed of different diameters of casing, tubing, and/or pipe. As an example, the string can taper wherein the top section is relatively large in diameter and the bottom section 1023 is much smaller in diameter. The string terminates at a bottom located opening 1024 which can be fitted with various and sundry known landing nipples supported by packers, bridge plugs and the like; they have been omitted for sake of clarity in the description of the string and the associated equipment.

In general, pipe extends to the bottom or nearly so where cement is delivered from the opening 1024. Cement flows into the annular space and is delivered into the space to complete the cementing job. This space has been represented in very general form in FIG. 10A and will be understood to be that portion of the wellbore where cement is to be delivered, and may, as desired, be defined and isolated by packers or bridge plugs. The annular space may also be temporarily or permanently filled with other fluids either before or after the cement, all for the purpose of completing the cement job and assuring that the cement bond between the string and well bore is completed in the desired fashion. The space is therefore set forth in very general form on the exterior of the string. This fact remains true even should there by multiple tubing strings to multiple zones along the well.

A flow meter 1015 and the other devices and transducers are may be input into the system CS which may include, as needed, a computer or computers and may be accessible on site and/or remotely. Graphic displays may be provided.

In one aspect, the annular space is filled by cement, cements, and/or fluids which are delivered serially. In one aspect, a first cement is pumped out the opening 1024 at the bottom end of the pipe and is a first cement 1044 which has a measured volume and hence stands to a certain height in the annular space and it is located above a subsequent amount of cement 1045. In one aspect, three cements are pumped into the annular space. As shown in FIG. 10B the cement 1044 has been moved upwardly. The cement 1045 has moved upwardly and it is supported by a third cement 1046 which has introduced therebelow, flowing into the annular space The three cements thus stand one on the other. There may be some interface between them and/or they may flow with a relatively sharp separation.

The cements may be isolated by adjacent slugs of other materials which can aid and assist in positioning the cements at the desired locations in the wellbore. This desired location may be delineated by suitable packers and bridge plugs. As is true for any embodiment herein, the cement (or any part thereof) may be heated to facilitate its curing, solidifying, and/or setting

A wellbore made as in FIGS. 10A-10C may have any device or system described herein for imposing a current on the nanomaterial in the cement.

As depicted in FIG. 11, a tubular string 1112 (such as a production, injection, drill, test or coiled tubing string) has been installed in a wellbore 1114 cased with casing 1124 cemented with cement 1126. The cement 1126 may be any cement according to the present invention which has sufficient electrically conducting nanomaterial NMA (not shown to scale) that, upon imposition of electric current thereon, heats the cement, and/or the casing, the interior of the casing, and/or the tubing, the interior of the tubing and/or the earth formation adjacent the casing. An electrical power generator 1116 is interconnected in the tubular string 1112. The generator 1116 generates electrical power from flow of fluid (represented by arrow 1118) through an internal flow passage 1120 of the tubular string 1112. Optionally, the generator 1116 is disposed on an interior wall of the casing.

The fluid 1118 is shown as flowing upwardly through the tubular string 1112 (as if the fluid is being produced), but it should be clearly understood that a particular direction of flow is not necessary in keeping with the principles of the invention. The fluid 1118 could flow downwardly (as if being injected) or in any other direction. Furthermore, the fluid 1118 could flow through other passages (such as an annulus 1122 formed radially between the tubular string 1112 and the wellbore 1114) to generate electricity, if desired.

The generator 1116 is illustrated as being electrically connected with lines 1131 and 1132 to the casing, but it is within the scope of the present invention for any connection, lines, cables, wireless apparatus, etc. disclosed herein to be used to connect the generator 1116 to the casing, or through the casing to the cement.

FIG. 12 illustrates a method 1200 according to the present invention in which material 1202 (“PRIMARY MATERIAL IN OR FOR USE IN A WELLBORE”) which has within it material 1204 that is heatable by the application of energy to it (“HEATABLE MATERIAL”). Energy is applied to the heatable material by an energy source 1206 (“ENERGY SOURCE”). The energy source 1206 is, as shown, spaced apart from the material 1202 or (as shown with the dotted lines) the energy source 1206 is in contact with the material 1202.

The material 1202 may be any material used in wellbore operations, including, but not limited to, drilling fluid, fracturing fluid, cement, polymers, composites, epoxy, epoxy systems, and two-part epoxies. The heatable material 1204 may be any known energy heatable material, e.g., but not limited to, microwave heatable material, resistively heatable electrically conductive material, and inductively heatable material heatable by the application of a magnetic field. The heatable material may be nanomaterial. The energy source may be any suitable source of energy, including, but not limited to, apparatus for applying microwaves, magnetic field apparatus such as apparatus with an induction coil, and a power source of electrical current.

In certain aspects of the present invention wellbores according to the present invention and methods according to the present invention employ a power source for imposing an electric current on electrically conductive nanomaterial. It is within the scope of the present invention to use any suitable known power source, battery, generator, capacitor, motor, or storage device for supplying the electrical current, including, but not limited to, those disclosed in U.S. Pat. Nos. 7,242,103; 7,699,102; 7,002,261; 7,133,325; 7,814,993; 7,717,167; 6,717,283; 6,672,409; 6,672,382; 6,554,074; 6,504,258; 6,470,970; 6,424,079; 6,179,052; 6,020,653; 5,995,020; 5,965,964; 5,626,200; 5,202,194; 4,416,000; 4,415,823; 4,215,426; 4,015,234; 3,968,387; and 3,448,305 and in each prior reference cited in each of these patents—all said patents and said references incorporated fully herein for all purposes; and the control systems, communications systems, cabling, wireless transmission apparatus etc. disclosed in these applications and patents, when suitable, may be used with the wellbores and the methods of the present invention.

It is within the scope of the present invention to use one, two, three or greater multiples of any energy source, etc. disclosed herein for a single wellbore, including, but not limited to, those of FIGS. 5A-5D and FIG. 11. It is also to be understood that the wellbore of FIG. 11 may have multiple zones with heatable material, with one or more energy sources. Any energy source used with embodiments according to the present invention that is movable may be selectively moved to any desired point in a wellbore or in a tubular (e.g., casing) to apply energy (electric current, magnetic field, and/or microwaves) at any desired location.

The present invention, therefore, provides in at least certain embodiments methods for cementing casing in a wellbore, the methods in certain aspects including cementing all of or at least a portion of a tubular, e.g., but not limited to, casing in a wellbore with cement that contains electrically conductive nanomaterial.

The present invention, therefore, provides in at least certain embodiments methods for heating cement in a wellbore, the methods in certain aspects including imposing an electrical current on at least a portion of cement, said at least a portion of cement containing electrically conductive nanomaterial that is heated upon the imposition of the electrical current, the cement being any cement used in a wellbore and, in one aspect, cement that cements casing in a wellbore.

The present invention, therefore, provides in at least certain embodiments methods for heating cement in a wellbore, the methods in certain aspects including methods for heating casing cemented in a wellbore with cement, the methods including imposing an electrical current on all of or at least a portion of cement that cements casing in a wellbore, said cement containing electrically conductive nanomaterial that is heated upon the imposition of the electrical current resulting in heating of the nanomaterial, said heating of the nanomaterial causing heating of the casing.

The present invention, therefore, provides in at least certain embodiments methods for heating contents of a tubular in a wellbore, the wellbore including cement therein, the methods in certain aspects including heating the contents within a wellbore (including, but not limited to contents within a tubular within a wellbore, including but not limited to the contents of casing or of tubing within a wellbore, including but not limited to the contents of tubing within casing in a wellbore, the methods including: imposing an electrical current on all of or at least a portion of cement in a wellbore, the wellbore having contents or a tubular within the wellbore having contents, said cement containing electrically conductive nanomaterial heated upon the imposition of the electrical current resulting in heating of the nanomaterial, said heating of the nanomaterial causing heating of the contents in the wellbore or causing heating of the tubular (e.g., tubing or casing), said heating resulting in heating of the contents. In such methods, in certain aspects, the contents is fluid, the fluid being one of drilling fluid, oil, gas, and water.

The present invention, therefore, provides in at least certain embodiments methods for heating earth formation adjacent cement in a wellbore, the cement in the wellbore or the cement around casing in the wellbore, the methods including: imposing an electrical current on all of or on at least a portion of cement that cements casing in a wellbore, said at least a portion of cement containing electrically conductive nanomaterial that is heated upon the imposition of the electrical current; said heating of the electrically conductive nanomaterial causing heating of the cement which in turn heats earth formation adjacent the cement. In certain aspects, such a method in which the earth formation contains fluid to be produced through the wellbore heating the earth formation heats the fluid to be produced.

The present invention, therefore, provides in at least certain embodiments methods for cementing a string of casing disposed in a well bore which includes a float collar connected near the bottom end thereof include the steps of: releasing a first displacement plug into said casing which is selectively openable after landing on said float collar; pumping a first displacement fluid behind said first displacement plug until said first displacement plug is displaced through said casing and lands on said float collar; causing said first displacement plug to open; pumping a cement slurry into said casing in a predetermined quantity required to fill the annulus between the exterior of said casing and the walls of said well bore with said cement slurry, said cement slurry containing electrical conductive nanomaterial which, upon the imposition of an electric current thereto, is resistively heatable; and releasing a top cementing plug into said casing and pumping a second displacement fluid behind said top cementing plug to displace said cement slurry through said casing and through said open displacement plug into said annulus. Such methods may include allowing the cement to set forming solid cement, and imposing an electric current on said electrical conductive nanomaterial to resistively heat the electrically conductive nanomaterial thereby heating the cement and/or imposing an electric current on said electrical conductive nanomaterial to resistively heat the electrically conductive nanomaterial thereby facilitating the setting of the cement.

The present invention, therefore, provides in at least certain embodiments methods for cementing a tubular string in a wellbore, the methods including making a wellbore in the earth, placing a tubular string in the wellbore, introducing cement into a space between an exterior of the tubular string and an interior of the wellbore, the cement containing electrically conductive nanomaterial which is resistively heatable, and allowing the cement to set. In such methods the cement can include amounts of different cements each different cement located generally at a different location in the space, and, optionally, each different cement having a different concentration of electrically conductive nanomaterial.

The present invention, therefore, provides in at least certain embodiments methods for heating cement that is in a wellbore and/or cement cementing casing in a wellbore, the methods including: imposing an electrical current on all of or on at least a portion of the cement, said cement containing sufficient electrically conductive nanomaterial so that the cement is heated upon the imposition of the electrical current, the electrical current supplied by a power source, the electrical current being one of alternating current and direct current, and, optionally, the power source controlled on-site or remotely by a control system. In such a method the power source may be any wired or wireless power source or generator, fixed or movable, and may be controlled by a control system that is one of on-site accessible and remotely accessible.

The present invention, therefore, provides in at least certain embodiments methods for heating cement that is in a wellbore and/or that is cementing casing in a wellbore, the methods including: imposing an electrical current on all of or on at least a portion of cement, said cement containing sufficient electrically conductive nanomaterial that the cement is heated upon the imposition of the electrical current; the electrical current supplied by a power source, the power source being located within earth formation adjacent the casing, within the cement, within the wellbore, at an earth surface, within the wellbore, or within the casing.

The present invention, therefore, provides in at least certain embodiments methods for heating cement that is in a wellbore or that is cementing casing in a wellbore, the methods including: imposing an electrical current on the cement, said cement containing electrically conductive nanomaterial that is heated upon the imposition of the electrical current, the cement including spaced-apart amounts of different cements each different cement located generally at a different location in the wellbore, and heating the different cements at the same time or at different times. Such methods may include one or some, in any possible combination, of the following: the different cements are one on top of the other and the heating is done from top to bottom of cements so that a lowermost cement is heated last or the different cements are one on top of the other and the heating is done from bottom to top of the different cements so that a lowermost cement is heated first; and/or each different cement has a different concentration of electrically conductive nanomaterial.

The present invention, therefore, provides in at least certain embodiments methods for cementing casing in a wellbore, the method including cementing a casing in a wellbore with cement that contains electrically conductive nanomaterial, the cement comprising a plurality of spaced-apart cements each with a different concentration of electrically conductive nanomaterial.

The present invention, therefore, provides wellbores with cement therein, the cement containing heatable electrically conductive nanomaterial. In certain aspects, the wellbore is cased with casing and the cement is heatable to heat the cement and/or to heat the casing an/or to heat things or fluids in contact with or near the heated cement and/or in contact with or near the casing.

It is within the scope of the present invention to provide a method for cementing a borehole that includes selecting a location in the borehole for cementing and providing a cement slurry including a cement (with or without nanomaterial therein, as any nanomaterial disclosed herein, with the nanomaterial dispersed or located therein in any way disclosed herein) and shape memory members with nanomaterial thereon and/or therein (as any nanomaterial disclosed herein, with the nanomaterial applied, coated, dispersed or located therein or thereon in any way disclosed herein) having a first shape, the shape memory members configured to expand from the first shape to a second shape upon application of heat to the shape memory members, placing the cement slurry in a selected space and heating the shape memory members in the selected space to attain the second shape. Such methods and shape memory members are improvements of those disclosed in U.S. Pat. No. 8,720,560 which is incorporated fully herein for all purposes.

FIG. 13 shows a diagram of an exemplary borehole system 1300 using shape memory members made according to one embodiment of the disclosure that may be utilized for cementing a borehole 1302. In an embodiment, a cement slurry 1303 (referred to as “slurry” or “cement”) is directed downhole to cement the borehole. Optionally, the cement slurry 1303 has nanomaterial therein (as any disclosed herein). The borehole 1302 may include vertical, directional, lateral and various degrees from vertical approaching lateral boreholes formed in a formation 1304 for storage and/or retrieval of fluids, such as sequestration or hydrocarbon production. As depicted, a tubular 1306 is disposed in the borehole 1302, wherein the tubular 1306 extends from surface 1310 to an end portion 1307 of the borehole. A derrick 1308 is located at the surface 130 to support borehole equipment, including the tubular 1306.

In the depicted embodiment, a slurry system 1312 is located proximate the surface. The slurry system 1312 is configured to direct the cement slurry 1303 downhole, as shown by arrows 1314 and 1316. The cement slurry 1303 is directed downhole by an additive source 1318, a slurry source 1320 and a pump 1322.

As depicted, the additive source 1318 provides an additive, such as shape memory members, to be mixed with a cement slurry in the slurry source 1320, prior to being directed downhole by the pump 1322. The shape memory members may include known shape memory members without nanomaterial according to the present invention in combination with shape memory members according to the present invention.

In another embodiment, the shape memory members are added to and mixed with the cement slurry prior to being placed in the slurry source 1320. Exemplary shape memory members are composed of a polymer material and have a density that is less than that of the cement slurry (with nanomaterial present at a selected loading level so that a desired density is achieved). Thus, the addition of shape memory members, in certain aspects, can reduce the density of the slurry.

An exemplary cement slurry includes dry cement combined with a water solution to create a wet cement or slurry (with or without nanomaterial therein). The water solution can be fresh water, drill water, sea water, brackish water, produced, flowback, mono-valent or di-valent brines or another water solution. This may be accomplished by use of selected mixers, including hydraulic jet mixers, re-circulating mixers or batch mixers (including, when present, use for mixing nanomaterial).

In an embodiment, shape memory members comprise a material with shape memory or shape-conforming materials (also referred to as “shape-memory materials”), members, apparatus and/or devices made using such materials and methods of their use. In one aspect, cement slurry additives are made from a suitable material, including, but not limited to, syntactic and conventional memory foams, a shape memory polymer (SMP), and/or a combination thereof. As used herein, the term “memory” refers to the capability of a material to withstand certain stresses, such as external mechanical compression, vacuum and the like, but to then return, under appropriate conditions, such as exposure to a selected form of energy, often heat, to the material's original size and shape. Any materials disclosed in U.S. Pat. No. 8,720,560 may be used. In certain aspects, the shape memory material may be described as having a “shape memory” property.

Still referring to FIG. 13, the initial (as-formed) shape of the shape memory member comprised of the shape memory material may vary, though a substantially spherical, cylindrical or squared shape is well-suited to be mixed and distributed within a cement slurry. In certain aspects, once the member of shape memory material is compressed and cooled, it is added to the cement slurry, which may then be directed downhole.

In an embodiment, the cement slurry is pumped along the tubular 1306 wherein it is released near the end portion 1307 of the borehole and directed into an annulus 1324, as shown by arrows 1316. The cement slurry may also be utilized to combat a “loss of circulation” zone which may occur in the wellbore or casing while drilling, static, production or completion operations are in process. The exemplary cement slurry then hardens in the desired location, such as annulus 1324, where the cement slurry as the shape memory members expand due to exposure to a activation, such as exposure to an appropriate temperature, e.g but not limited to a temperature greater than the shape memory members' glass transition temperature (“GTT”). For example, and not by way of limitation of the scope of the present invention, shape memory members are first heated to a temperature above the shape memory members' GTT and compressed to a first shape and then cooled to retain the compressed shape. An exemplary GTT of the shape memory members is about 150 degrees F.

In one aspect, the compressed shape memory members are then added to a cement slurry proximate the surface 1310, wherein the cement slurry and shape memory members are maintained at a desired temperature, e.g. but not limited to less than about 130 degrees F., such as about 100 degrees F.

The cement slurry and the shape memory members are then directed into the desired location, such as annulus 1324, by the pump 1322, between the tubular 1306 and borehole 1302 wall. In one embodiment, the temperature of formation 1304 and borehole 1302 is higher than the shape memory member GTT, and thus causes the shape memory members to expand to a second expanded shape. Thus, a downhole treatment, such as by heating or exposing to an activating agent, causes the shape memory members to expand, e.g. but not limited to for filling cracks that may form in the cement during hydrating and/or hardening. Exemplary borehole 1302 temperatures include a temperature about equal to or greater than 150 degrees F.

After being directed to a selected location in the borehole 1302, the shape memory members expand during hardening of the slurry, e.g., but not limited to, to reduce development of cracks in the hydrating cement thereby preventing flow of formation fluid into the annulus 1324. Further, the shape memory members can expand within the cement slurry to conform the slurry as it hardens or sets to contours of the borehole 1302 walls. Thus, the shape memory members, in certain aspects, added to the cement slurry can improve sealing and isolation of selected cemented areas of the borehole 102.

In addition, in certain embodiments, the shape memory members can cause a reduction in density.

FIGS. 14A and 14B are views of exemplary embodiments of a shape memory member 1330 to be added to a cement slurry, as discussed above. The depicted shape memory member 1330 is spherical, but it should be understood that the members may be any suitable shape. The shape memory member 1330 comprises a shape memory material, such as, but not limited to a shape memory polymer. Nanomaterial 1336 (not shown to scale in this Figure nor in FIGS. 14B-15D) is within the shape memory member 1330.

FIG. 14A illustrates the shape memory member 200 in a compacted shape; in one aspect, the shape memory member 1330 is compacted at a temperature at or above a GTT of the shape memory material, then cooled below the GTT. The compacted shape memory material has a diameter 1332. The depicted shape memory member 1330 is added to a cement slurry and directed downhole, as described above.

FIG. 14B illustrates the shape memory member 1330 in an expanded shape, wherein the shape memory material is heated so that it expands. In one particular aspect, it is heated to a temperature about equal to or greater than the GTT of the shape memory material. After being directed downhole and into the annulus 1324, the shape memory member 1330 is heated to a desired temperature.

The depicted shape memory member 1330 has a diameter 1334 when expanded, wherein the diameter 1334 is greater than diameter 1332. For other shapes, a largest dimension of the member is greater after heating.

FIG. 15A shows a shaped memory member 1500 according to the present invention which has therein nanomaterial 1505 (which, optionally, may be deleted). A coating 1502 on the shaped memory member 1500 has nanomaterial 1504 therein. Any suitable known coating with nanomaterial may be used, including, but not limited to, those disclosed and those referred to in U.S. application Ser. No. 13/998,093 filed 30 Sep. 2013.

FIG. 15B shows a shaped memory member 1506 according to the present invention which has therein nanomaterial 1507 (which, optionally, may be deleted). An intermittent coating 1508 (which contains nanomaterial) covers less than the entire surface of the shaped memory member 1506. Any suitable known coating with nanomaterial may be used, including, but not limited to, those disclosed and those referred to in U.S. application Ser. No. 13/998,093 filed 30 Sep. 2013.

FIG. 15C shows a shaped memory member 1510 according to the present invention which has therein nanomaterial 1514 (as any disclosed herein) which, optionally, may be deleted. A partial coating 1512 (which contains nanomaterial) covers less than the entire surface of the shaped memory member 1510. Any suitable known coating with nanomaterial may be used, including, but not limited to, those disclosed and those referred to in U.S. application Ser. No. 13/998,093 filed 30 Sep. 2013.

It is within the scope of the present invention to coat all or part of a shape memory member (containing nanomaterial or not) with a coating with nanomaterial therein (e.g., but not limited to, as shown in FIGS. 15A-15D. Such a coating may facilitate the heating of a shape memory member. Such a coating may strengthen a shape memory member. Such a coating may assist desired expansion of a shape memory member. Such a coating may facilitate expansion of a memory member so that it does not expand uniformly or regularly, but rather expands nonuniformly and/or nonregularly, producing instead of a smooth regular shape (such as, e.g., a uniform sphere or a uniform ovoid or cylinder) an irregular shape, a non-smooth shape, or both.

FIG. 15C shows a shape memory member 1510, optionally with nanomaterial 1514 therein, which has a coating with nanomaterial 1512 which does not cover all the surface of the shape memory member 1510. FIG. 15D shows the shape memory member 1510 after expansion (due to heat, contact with appropriate fluids or materials, or both— as may be true for any shape memory member herein). The coating 1512 has separated into separate portions and the shape memory member 1510 has expanded into an irregular shape.

It is within the scope of the present invention to provide cement compositions with nanomaterial therein, any nanomaterial disclosed herein; and, in certain aspects, such compositions with biowaste ash which are improved versions of those disclosed in U.S. Pat. No. 8,733,440 (incorporated fully herein for all purposes). Examples of suitable biowaste ash include agricultural waste ash, municipal waste ash, waste-water treatment waste ash, animal waste ash, non-human-non-animal industrial waste ash, and combinations thereof. The cement composition may include any suitable cement, e.g., but not limited to, known cements used in wellbores, Portland cement, a pozzolana cement, a gypsum cement, a high-alumina-content cement, a slag cement, a silica cement, and combinations thereof.

In certain aspects, such compositions are used in a method of well cementing including: introducing a cement composition according to the present invention into an annulus between a subterranean formation and a pipe string disposed in the subterranean formation, wherein the cement composition is, e.g., an hydraulic cement including at least one cement which is one of a Portland cement, a pozzolana cement, a gypsum cement, a high-alumina-content cement, a slag cement, a silica cement, and combinations thereof, water in an amount sufficient to form a pumpable slurry, e.g. in some aspects present between about 40% to about 200% by weight of the cementitious components; and, optionally, biowaste ash; and optionally biowaste ash that does not include fly ash or rice hull ash; and allowing the cement composition to set. Optionally, the nanomaterial in the composition is used to facilitate setting of the cement due to enhanced thermal transfer and/or the nanomaterial increases strength of the cement.

Such a cement composition according to the present invention may have nanomaterial present at any desired loading level, including those disclosed herein. Such a composition may include at least one additive, e.g., one of a strength-retrogression additive, a set accelerator, a set retarder, a weighting agent, a lightweight additive, a gas-generating additive, a mechanical property enhancing additive, a lost-circulation material, a filtration control additive, a dispersant, a fluid loss control additive, a defoaming agent, a foaming agent, a thixotropic additive, oil-swellable materials, water-swellable materials, crystalline silica, amorphous silica, fumed silica, a salt, fiber, hydratable clay, calcined shale, a microsphere, pumicite, diatomaceous earth, an elastomer, a resin, latex, and combinations thereof (as may any cement or composition disclosed herein).

It is within the scope of the present invention to provide a tubular, a coating for a tubular, and a system including: a tubular containing a first surface including a coating made of a first swellable material (optionally with nanomaterial therein) coating the first surface, the coating having a second surface and the first swellable material comprising a selectively swellable material, the first swellable material able to swell in response to a property change, a temperature change, upon contact with an agent that induces swelling, or upon coming in contact with a first fluid on the second surface; and a composition made of a settable material (with or without nanomaterial therein) and a second swellable material (with or without nanomaterial therein) able to swell in swell in response to a property change, a temperature change, upon contact with an agent that induces swelling, or upon coming in contact with a second fluid on the second surface. Such a coating, such a tubular, and such a system according to the present invention are improvements over these things as disclosed in U.S. Pat. No. 8,689,894 which is incorporated fully herein for all purposes.

In certain aspects, the present invention provides materials and methods using them for reducing or eliminating wellbore zonal isolation problems by providing a reliable annular seal between a formation and a casing, using a swellable material (with or without nanomaterial therein) associated with an adaptive settable material (with or without nanomaterial therein). In certain aspects, the coating for a tubular is flexible swellable material with nanomaterial therein which is able to dissipate or distribute a stress load from a tubular, decreasing stress on settable material adjacent the tubular. Such a coating can be on an inner surface of a tubular, on an outer surface, or both.

FIG. 16A shows one aspect of the invention, a system 1610 is disclosed which has the association of a flexible swellable coating attached to a tubular 1600 and of an adaptive cement or more generally to a settable material with a second swellable material. The tubular 1600 having an internal surface 1612 and an outer surface 1611. The tubular 1600 is shown as substantially cylindrical with a flow channel therethrough, but any suitable shape and configuration tubular may be within the scope of this invention. The tubular shown is hollow, but it may be solid for other uses and embodiments.

The tubular comprises a coating 1602 made of a first swellable material 1603 able to swell in response to a selected stimulus or agent, e.g., but not limited to, in response to heat and/or in response to contact with a first fluid 1606. The coating 1602 has an internal surface 1622 and an outer surface 1621. The coating is shown as substantially cylindrical, but it may be any desired shape, dimensions, and/or configuration; and the coating may be securely attached to the outer surface of the tubular 1600 via the inner surface of the coating 1622. Attachment can be made by any structure, fastener, or type of system: e.g., glue, hot melting, hot vulcanization, screwing, interlocking, etc.

The first fluid 1606 may be any type of suitable fluid, which may be liquid or gaseous or multi-phasic. In certain aspects, the fluid is aqueous or non-aqueous e.g. water, oil or hydrocarbon-based fluids, solvents, gases, fluids from the formation, wellbore fluids, drilling fluids, fluids pumped from surface or a combination thereof. The first swellable material is able to swell in response to an agent, a property change, and/or upon contact with the first fluid 1606. Swellable materials means as defined, that the material can swell, i.e. increases its volume or its apparent volume, e.g., but not limited to, like a sponge. In certain aspects, the first swellable material remains in a swollen state when still subjected to first fluid.

The coating is, in certain aspects, entirely made of a uniform layer of swellable material coating the tubular, with any desired thickness and can be any coating disclosed or referred to herein; e.g., but not limited to, between 0.2 millimeters and 10 Centimeters or as thick as any coating disclosed in U.S. application Ser. No. 13/998,093 filed 30 Sep. 2013. The coating may be flexible. By flexible it is meant that the coating has an elasticity allowing a deformation of the geometry when subjected to rolling, folding, stress or tension. In certain aspects, it is able to dissipate anr/or distribute a stress load from the tubular thereby decreasing stresses on the settable material. In certain aspects, the risk of crack formation is reduced by the presence of a flexible coating around the tubular, its role being to spread the stress load applied on settable material adjacent the tubular; and crack formation in the set material is eliminated or reduced.

The material of the coating may be made of a water-swellable elastomer, a hydrocarbon-swellable elastomer, a gas-swellable elastomer or a combination of both. It may be made of a composite material and comprise further other materials. For example, it may include fillers. The fillers may be water-swellable, gas-swellable, oil-swellable or swellable to both oil and water or/and gas. Suitable water-swellable materials include acrylic acid type polymers, carboxymethyl cellulose type polymers, highly swelling clay minerals, isobutylene maleic anhydride, polyethylene oxide polymers, polyvinyl alcohol cyclic acid anhydride graft copolymer, sodium bentonite (montmorillonite), starch polyacrylate acid graft copolymer, starch polyacrylonitrile graft copolymers, vinyl acetate-acrylate copolymers, and combinations thereof.

Suitable hydrocarbon-swellable (oil and/or gas) materials include natural rubber, polyisoprene rubber, vinyl acetate rubber, polychloroprene rubber, acrylonitrile butadiene rubber, hydrogenated acrylonitrile butadiene rubber, ethylene propylene diene monomer, ethylene propylene monomer rubber, polynorbornen, styrene butadiene rubber, styrene/propylene/diene monomer, brominated poly(isobutylene-co-4-methylstyrene) (BIMS), butyl rubber, chlorosulphonated polyethylenes, polyacrylate rubber, polyurethane, silicone rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, epichlorohydrin ethylene oxide copolymer, ethylene acrylate rubber, ethylene propylene diene terpolymer rubber, sulphonated polyethylene, fluoro silicone rubbers, fluoroelastomer, substituted styrene acrylate copolymer, and combinations thereof.

As shown in FIG. 16A, a composition 1620 in contact with the tubular or adjacent thereto, is made of a settable material 1605 and a second swellable material 1604. The second swellable material 1604 is able to swell in response to an agent, in response to a property change, or upon contact with a second fluid 1607. In certain aspects, the second swellable material remains in a swollen state when still subjected to the second fluid.

The second fluid 1607 may be any type of fluid, which may be liquid or gaseous or multi-phasic. The first and the second fluids can be the same, or different. In certain aspects, the second fluid is aqueous or non-aqueous e.g. water, oil or hydrocarbon-based fluids or a combination thereof. In certain aspects, the second swellable material 1604 is substantially inactive during reaction of the first fluid 1606 with the first swellable material 1603. Thus, in certain aspects, there is a delay in activation of the swellable materials: firstly, the coating 1602 activates and after the second swellable material activates within the settable material 1605. Accordingly, the settable material 1605 can be preferentially set when activation of the second swellable material 1604 occurs.

The settable material 1605 is any type of material that has the ability to go from a fluid state to a solid state with time, temperature, pressure changes, or under any physical or chemical stimulus. For example, examples of settable material are: cement, geopolymer, plaster, resin. In certain aspedts, the settable material is a cementing composition 1630 comprising an hydraulic binder, in general based on a suitable cement, e.g. a Portland cement (or another type of hydraulic material) and water. Depending on the specifications regarding the conditions for use, the cementing compositions can also be optimized by adding additives common to cementing compositions such as dispersing agents, anti-foaming agents, expansion agents (for example calcium oxide or magnesium oxide), fluid loss control agents, gas migration control agents, retarders, accelerators or still anti-settling agents, or additives of the type. In certain aspects, formulations are based on Portland cement in classes A, B, C, G and H as defined by ISO/API standards; and Classes G and H Portland cements may be used, as well as other cements which are known in this technology area. For low temperature applications, aluminous cements and Portland/plaster mixtures or cement silica mixtures for wells exceeding 120.degree. C. can be used.

The second swellable material 1604 is able to swell in contact with the second fluid 1607. As disclosed previously, when the settable material is cement, the second swellable material 1604 may be rubber, in particular styrene butadiene rubber and ground rubber, poly 2,2,1-bicyclo-heptene(polynorbornene), alkylstyrene, rosslinked substituted vinyl-acrylate copolymers and diatomaceous earth. Mixtures of two or more of these materials can also be used, in particular to provide cement that is susceptible to react to a large variety of ubterranean hydrocarbons. The composition made of the cement and the second swellable material can also be called an adaptive cement system. Adaptive cement systems refers to cement systems which are self-healing or self-repairing, i.e. systems which can adapt to compensate for changes or faults in the physical structure of the cement, or which adapt their structure in the cementing of oil, gas, water or geothermal wells, or steam injection wells or wells with Enhanced Oil Recovery (EOR) or gas storage wells or the like. In addition to the specific self-healing additives able to swell in contact with reservoir fluid (hydrocarbon and/or water), the second swellable material can be flexible. In this way, the potential combination of flexibility and toughness can extend the range of mechanical properties of the settable system and second swellable material to extreme conditions.

In another embodiment, the adaptive cement design can also contain flexible particles and/or fibers to improve respectively the flexibility and/or the toughness of the set material.

It is within the scope of the present invention to provide nanomaterial, e.g. but not limited to carbon nanotubes, to any swellable material, coating, and/or settable material used in systems according to the present invention, e.g. but not limited to, as in FIGS. 16A and 16B. As shown in FIG. 16A, nanomaterial 1640 (shown by squiggly lines, not to scale) may be dispersed throughout the coating 1602 in the material 1603 (only a few squiggly lines shown which indicate nanomaterial througOut the coating and the material) nanomaterial 1641 throughout the settable material 1605; and/or nanomaterial 1643 throughout the swellable material 1604. The nanomaterial may be any suitable known nanomaterial, including but not limited to, those disclosed herein, at any loading level disclosed or referred to herein. In certain particular aspects, there is sufficient nanomaterial 1640, 1641, and/or 1642 present to facilitate swelling of the swellable material, setting of settable material, and/or to facilitate the conveyance of heat to the settable material in contact with or adjacent the tubular and/or to facilitate heating of earth 1609.

The tubular, e.g. the tubular in FIGS. 16A and 16B, may be a casing in a wellbore and the settable material may be cement cementing the casing in the wellbore. The material 1630 may be a cement slurry pumped down an annulus between the casing and the wellbore.

Methods according to the present invention using swellable material according to the present invention and/or settable material according to the present invention may be used for various types of applications: e.g., primary cementing, steam injection, Steam Assisted Gravity Drainage (SAGD), plug and abandonment, geothermal wells, gas storage well, and heavy oil applications.

In conclusion, therefore, it is seen that the present invention and the embodiments disclosed herein and those covered by the appended claims are well adapted to carry out the objectives and obtain the ends set forth. Certain changes can be made in the subject matter without departing from the spirit and the scope of this invention. It is realized that changes are possible within the scope of this invention and it is further intended that each element or step recited in any of the following claims is to be understood as referring to the step literally and/or to all equivalent elements or steps. The following claims are intended to cover the invention as broadly as legally possible in whatever form it may be utilized. The invention claimed herein is new and novel in accordance with 35 U.S.C. §102 and satisfies the conditions for patentability in §102. The invention claimed herein is not obvious in accordance with 35 U.S.C. §103 and satisfies the conditions for patentability in §103. The prior text of this specification is in accordance with the requirements of 35 U.S.C. §112. The inventor may rely on the Doctrine of Equivalents to determine and assess the scope of their invention and of the claims that follow as they may pertain to apparatus and/or methods not materially departing from, but outside of, the literal scope of the invention as set forth in the following claims. All patents and applications identified herein are incorporated fully herein for all purposes. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements. 

What is claimed is: 1.-109. (canceled)
 110. A method comprising making a wellbore in the earth, placing a tubular string in the wellbore, introducing primary material into a space between an exterior of the tubular string and an interior of the wellbore, the primary material containing heatable material, allowing the primary material to solidify, facilitating solidifying of the primary material with heat, the heat generated by applying energy to the heatable material thereby heating the heatable material, wherein the heatable material is one of or a combination of electrically resistively heatable material, microwave heatable material, magnetically heatable material, inductively heatable material, nanotubes, nanographene, nanographene ribbons, transformed nanomaterials, carbon nanomaterials, electrically conductive nanotubes, carbon nanotubes, single-walled nanotubes, multi-walled nanotubes, double walled nanotubes, and surface-modified nanotubes.
 111. The method of claim 110 wherein solidifying of the primary material is one of hardening, setting, and curing.
 112. The method of claim 110 wherein the primary material is cement.
 113. The method of claim 110 wherein the primary material is one of epoxy, two-part epoxy, and epoxy system.
 114. The method of claim 110 further comprising after the primary material has solidified, re-heating the heatable material to again heat the primary material to heat other material adjacent the primary material.
 115. The method of claim 114 wherein the primary material includes a plurality of spaced-apart portions, the method further comprising selectively heating each portion.
 116. The method of claim 110 wherein the primary material includes a plurality of spaced-apart portions each of which is heated according to a program which is one of: simultaneously heating all portions; selectively heating a portion or portions; sequentially heating the portions from top to bottom of the wellbore; and sequentially heating the portions from bottom to top of the wellbore.
 117. The method of claim 110 wherein the heatable material is heated by an energy source, the method further comprising heating the heatable material by applying energy to the heatable material the energy source which is one of: power generator; magnetic field apparatus; magnetic field generator; induction coil apparatus; microwave apparatus; microwave generator; a power source at an earth surface; a power source within earth; a power source within the wellbore; a power source within the tubular string; and wherein the tubular string is casing a power source within the casing.
 118. The method of claim 110 wherein the primary material is swellable material, the method further comprising swelling the swellable material by heating the swellable material by heating the heatable material.
 119. The method of claim 118 wherein the heatable material is nanomaterial.
 120. The method of claim 118 wherein the swellable material has nanomaterial therein.
 121. The method of claim 118 wherein the swellable material has coating material thereon, the coating material containing nanomaterial.
 122. The method of claim 110 wherein the primary material is shape memory material with nanomaterial therein, thereon, or both.
 123. A method for applying heat to material useful in wellbore operations, the material in a wellbore or material that is to be introduced into or used within a wellbore, the material to be heated containing secondary material, the secondary material being one of or a combination of resistively heatable electrically conductive material, resistively heatable nanomaterial, inductively heatable material, inductively heatable nanomaterial, microwave heatable material, microwave heatable nanomaterial, and carbon nanomaterial; the method including heating the material useful in wellbore operations by heating the secondary material, said heating of the secondary material done by using apparatus for applying to the secondary material energy to effect heating, the apparatus corresponding to the material, the apparatus being one of power source for applying electric current to the secondary material, magnetic apparatus for applying a magnetic field to the secondary material, and microwave apparatus for applying microwaves to the secondary material; and the heating of the secondary material facilitating one of hardening, setting, and curing of the material useful in wellbore operations.
 124. The method of claim 123 further comprising heating the secondary material above ground, within a wellbore, within a structure downhole, or within a structure above ground.
 125. The method of claim 123 wherein the material useful in wellbore operations is one of shape memory material and swellable material.
 126. A material with nanomaterial therein, the material comprising one or a combination of shape memory material and swellable material, the material comprising sufficient nanomaterial dispersed in the material to effect at least one of: strengthening the material for use in a wellbore, increasing thermal conductivity of the material; rendering the material signal-conductive; and rendering the material electrically conductive; the nanomaterial present as 0.1 weight percent to 10 weight percent of the material.
 127. The material of claim 126 wherein the nanomaterial is one or a combination of nanotubes, nanographene, nanographene ribbons, transformed nanomaterials, carbon nanomaterials, electrically conductive nanotubes, carbon nanotubes, single-walled nanotubes, multi-walled nanotubes, double walled nanotubes, and surface-modified nanotubes.
 128. The material of claim 126 wherein the material is in pieces, the material further comprising a coating on pieces of the material, the coating containing nanomaterial.
 129. The material of claim 126 wherein the pieces have an outer surface and the coating covers one of: less than all of the outer surface; all of the outer surface; or spaced-apart discrete amounts of the outer surface. 